1. Field of Invention
This invention relates to the field of methods of measuring water and hydrates content in production fluids. More particularly, it relates to methods and apparatuses for measuring water in multiphase production fluid flows.
2. Background Art
Many fluids, such as hydrocarbon production fluids, contain a certain proportion of water. Generally this water is in one of two forms, either as liquid water, or hydrocarbons hydrates. These hydrates are ice-like minerals that form at moderately low temperatures and high pressures of the deep sea and some land applications. They contain a molecule of hydrocarbons to which 4 or more molecule of water bond themselves in a symmetrical cages to form hydrate crystals. Regardless of form, however, the presence of water along with the more desired components of the production fluid, such as oil, is often problematic. If in liquid form, the water must eventually be removed in order to enable refining. If in hydrate form, the water plays a part in plugging pipelines and presenting transportation and storage difficulties.
Because of the significance of the presence of water in either form, it is frequently desirable to be able to first accurately measure it and detect in which state it is, liquid with or without hydrates solid particles. Such measurement is crucial to a number of subsequent decisions and operations adjustments, which may be of a financial, allocation, control or safety type. However, many of today's methods of determining the proportion of the so-called “water cut”, i.e., the proportion of the production fluid which is water in either liquid or hydrate form, are inaccurate as each hydrocarbon has different permittivity and or density. So unless individual calibration is performed, large error levels may result that can be as high as 5 percent. Current water cut meters are particularly susceptible to this high error level. This inaccuracy is often unacceptable.
For example, one known method is to measure the water cut by measuring the permittivity properties of the mixture. Permittivity is a physical quantity that describes how an electric field affects, and is affected by, a medium, according to the ability of that medium to polarize in response to the field. This method, unfortunately, is subject to systematic error. This systematic error results from the differences in the complex permittivity of different crude oils. These crude oils may be of highly complex composition and may include, for example, aliphatic and aromatic hydrocarbons of varying polarities, and various isomers thereof; molecules containing heteroatoms such as nitrogen, oxygen, sulphur or metals; resins and asphaltenes containing a wide variety of chemical groups such as naphthalenic acids, carboxylic acids, phenols, pyridines, thiophenols, benzothiophenes, alkylphenols, thiophenes, and other compounds whose substituents contribute to a relatively high level of polarity; salts; and, of course, water. Prior art methods have, however, failed to fully acknowledge this complexity of composition by using only overall density in its determination of complex permittivity. This density is converted to a dry crude oil dielectric constant (also known as the real part of complex permittivity) based upon an API gravity chart for zero shift compensation. However, because it is possible for two different dry crude oils, of different compositions, to have the same density but different dielectric constants, the dielectric constant is likely to be incorrect for the composition as a whole. Thus, even extremely accurate measurements of crude oil density may result in a crude oil dielectric constant with an error equivalent to 0.7 to 1.0 percent of water cut value. This degree of error is considered to be very high in many applications. Importantly, this method is also generally unsuited to in-line use in multiphase flows of production fluid.
Another method, geared particularly toward use where hydrates are being formed, involves simply detecting water in conjunction with measuring fluid pressure and temperature, and then performing an appropriate thermodynamics calculation therefrom. The drawback to this indirect method is that chemically active additives, such as methanol, salt, glycol and some other substances, substantially affect these calculations. Other indirect methods include those that look at either the effects produced by the hydrates, or the properties and structure of the hydrates, from which quantification is calculated rather than actually measured. These methods include both laboratory scale and industrial scale methods, including those based upon an array of instrumentation such as nuclear magnetic resonance (NMR) spectroscopy, Raman spectroscopy, and mass spectroscopy, sonic attenuation and propagation, fiber optic technology, volume-pressure-time relations, volume resistivity, and the like. Use of calculations rather than actual measurement, however, again leaves significant room for error.
As should be evident from the volume of references identified hereto, the detection of water in whatever form in a fluid media has received significant attention by many researchers. Generally speaking, the focus of attention of such research centered on the properties of hydrates rather than devising practical instruments for detecting the formation of hydrates and measuring their concentration, without prior knowledge of the properties of the hydrocarbons and salinity of the water in the conduit.
Thus, what is needed in the art is a method and apparatus for directly measuring the amount of water, in either liquid or hydrate form, in a multiphase production fluid flow, which reduces the error that frequently results from previously known methods and/or apparatuses. What is also needed in the art is a method and apparatus than can provide accurate measurements of water cut in crude oil without advance knowledge of properties of a particular dry crude oil.